Methods for stimulating hydrocarbon-bearing formations

ABSTRACT

A method for the stimulation of a hydrocarbon-bearing formation, said method comprising the steps of:
         providing a wellbore in need of stimulation;   inserting a plug in the wellbore at a location slightly beyond a predetermined location;   inserting a perforating tool and a spearhead or breakdown acid into the wellbore;   positioning the tool at said predetermined location;   perforating the wellbore with the tool thereby creating a perforated area;   allowing the spearhead acid to come into contact with the perforated area for a predetermined period of time sufficient to prepare the formation for stimulation;   removing the tool form the wellbore; and   initiating the stimulation of the perforated area using a stimulation fluid.       

     Also disclosed is a corrosion inhibiting composition for use with the acid composition.

CROSS-REFERENCE TO RELATED APPLICATION

This application claims the benefit of and priority to CanadianApplication No. 3,004,675, filed May 11, 2018. The entire specificationand figures of the above-referenced application is hereby incorporatedin its entirety by reference.

FIELD OF THE INVENTION

This invention relates to method for performing enhanced recoveryoperations on a hydrocarbon-bearing stimulation, more specifically to anacidic composition and a method to enhance well productivity forsubstantially reducing time and water use when performing hydraulicfracturing operations.

BACKGROUND OF THE INVENTION

In the oil & gas industry, stimulation with an acid is performed on awell to increase or restore production. In some instances, a wellinitially exhibits low permeability, and stimulation is employed tocommence production from the reservoir. In other instances, stimulationor remediation is used to further encourage permeability and flow froman already existing well that has become under-productive due to scalingissues or formation depletion.

Acidizing is a type of stimulation treatment which is performed above orbelow the reservoir fracture pressure in an effort to initiate, restoreor increase the natural permeability of the reservoir. Acidizing isachieved by pumping acid, predominantly hydrochloric acid, into the wellto dissolve typically limestone, dolomite and calcite cement between theacid insoluble sediment grains of the reservoir rocks or to treat scaleaccumulation.

There are three major types of acid applications: matrix acidizing,fracture acidizing, and breakdown acidizing (pumped prior to afracturing pad or cement operation in order to assist with formationbreakdown (reduce fracture pressures, increased feed rates), as well asclean up left over cement in the well bore or perforations.

A matrix acid treatment is performed when acid is pumped into the welland into the pores of the reservoir formation below the fracturepressure. In this form of acidization, the acids dissolve the sedimentsformation and/or mud solids that are inhibiting the permeability of therock, enlarging the natural pores of the reservoir (wormholing) andstimulating the flow of hydrocarbons to the wellbore for recovery.

While matrix acidizing is done at a low enough pressure to keep fromfracturing the reservoir rock, fracture acidizing involves pumping acidinto the well at a very high pressure, physically fracturing thereservoir rock and etching the permeability inhibitive sediments. Thistype of acid treatment forms channels or fractures through which thehydrocarbons can flow, in addition to forming a series of wormholes. Insome instances, a proppant is introduced into the fluid which assists inpropping open the fractures, further enhancing the flow of hydrocarbonsinto the wellbore. There are many different mineral and organic acidsused to perform an acid treatment on wells. The most common type of acidemployed on wells to stimulate production is hydrochloric acid (HCl),which is useful in stimulating carbonate reservoirs.

It has been estimated that fracking can improve the production of a wellby at least 10-20%. Also, as is well known to the person of ordinaryskill in the art, a well can be fracked multiple times during itsproduction life. The process of hydraulic fracturing or frackingrequires the following steps. Once the determination of the wellbore'sintegrity has been assessed, the location of the perforations isdetermined. Subsequently, after a cement liner is in place, one mustclear out the debris, and pump a plug and perforating guns to a desireddepth and location. The plug is set slightly beyond the desired locationto be stimulated and then the cemented liner in that zone is perforatedby using perforating guns, creating a path for fracking fluid to beforced into the shale formation.

The final stage prior to fracking requires the use of perforating guns,typically a string of shaped charges lowered to a predetermined locationwithin the wellbore. Once in position, the perforating gun is dischargedand perforates the casing.

According to the conventional process, after perforation stage iscompleted, the tools are removed from the well. A ball is pumped down toisolate the zones below the plug. This process applies to solid bridgeplugs (no ball) with which process it is required to squeeze wellborefluid into the perforations at low or reduced rates until acid reachesthe perforations and increases permeability to initiate a fracture andreduce injection pressures.

A large volume of fracturing fluid is then pumped into the desiredformation in a well. The high-pressure at which the fracturing fluid ispumped coupled with the constant pumping provide an increase in thefluidic pressure within the formation which leads to fracturing insidethe reservoir.

After the fracturing pressure is reached fracturing fluid containingpropping agents are injected into the formation to increase thefractures within the formation and insert proppant to maintain thefractures open. The last step of the fracturing operation before beingput back into production is to flush the well form all the looseproppants and fracturing fluids.

A slickline is a single strand wire used in the oil and gas industry totransport tools within a well. It is typically a single wire strand setup on a spool located on what is referred to as a slickline truck. Aslickline is connected by the drum it is spooled off the back of theslickline truck. A slickline is used to lower tools within a wellbore inorder to perform a specific operation.

In highly deviated wells, coiled tubing can be used to transport and tolower the perforation guns into position, i.e. at a predeterminedlocation. Modern slicklines allow to incorporate fiber optic lines whichcan communicate real time information to the operator regarding thedepth, temperature and pressure. This type of information provides oilwell operators sufficient information to perform a plug and perforationoperation by accurately targeting desirable hydrocarbon-bearingformations.

The benefit of this strategy is greater control of the well. Casing thebottom of the hole allows the well to be completed without having toworry about reservoir fluids. It also allows the operator to select theformation which will be fracked in order to obtain increased wellproduction. It also allows the operator to seal off perforated sections,which have had their hydrocarbons extracted.

When perforations are performed they may sometimes lead to skin damagecaused by debris from the perforations to limit or reduce theproductivity of a well (i.e. more specifically the targetedhydrocarbon-bearing formation) from the fracking operation.

Accordingly, in light of the state of the art of fracking, there stillexists a need to develop a method which reduces the waste of water. Theresolution of this problem lies in combining a chemical composition withthe mechanical tools in order to achieve a more efficient oil recoveryprocess.

SUMMARY OF THE INVENTION

It is an object of the present invention to provide for a novel methodfor fracking a well which overcomes some drawbacks of the known priorart processes. According to a first aspect of the present inventionthere is provided a method for the fracking or stimulation of ahydrocarbon-bearing formation, said method comprising the steps of:

-   -   providing a wellbore in need of stimulation;    -   inserting a plug in the wellbore at a location slightly beyond a        predetermined location;    -   inserting a perforating tool and a spearhead or breakdown acid        into the wellbore;    -   positioning the tool at said predetermined location;    -   perforating the wellbore with the tool thereby creating a        perforated area;    -   allowing the spearhead acid to come into contact with the        perforated area for a predetermined period of time sufficient to        prepare the formation for fracking or stimulation;    -   removing the tool form the wellbore; and    -   initiating the fracking of the perforated area using a fracking        fluid.

Preferably, the spearhead acid comprises a corrosion inhibitor adaptedto prevent damaging corrosion to the tool during the period of exposurewith said tool.

Preferably, the perforating tool is a perforating gun.

Preferably also, the spearhead acid is selected from the groupconsisting of: mineral acids; organic acids; modified acids; syntheticacids; and combinations thereof. More preferably, the spearhead acidfurther comprises a corrosion inhibitor. Even more preferably, thespearhead acid is selected from the group consisting of:methanesulphonic acid; HCl:amino acid; HCl:alkanolamine. Preferably, theamino acid is selected from the group consisting of: lysine; lysinemonohydrochloride; alanine; asparagine; aspartic acid; cysteine;glutamic acid; histidine; leucine; methionine; proline; serine;threonine; valine; and combinations thereof. Preferably also, thealkanolamine is selected from the group consisting of: monoethanolamine;diethanolamine; triethanolamine and combinations thereof.

According to a preferred embodiment of the present invention there isprovided a corrosion inhibiting composition for use with an acid, saidcomposition comprising: citral and/or cinnamaldehyde. Preferably, thecorrosion inhibiting composition comprises: an alkyne alcohol; aterpene, preferably selected from the group consisting of: citral;carvone; ionone; ocimene; cymene; and combinations thereof, mostpreferably the terpene is citral; cinnamaldehyde or a derivativethereof; and a solvent. More preferably, the corrosion inhibitingcomposition further comprises at least one surfactant.

Preferably, the alkyne alcohol is propargyl alcohol.

Preferably, the solvent is selected from the group consisting of:methanol; ethanol; a 6,3-ethoxylate; and isopropanol. More preferably,the solvent is isopropanol.

Preferably, the alkyne is present in an amount ranging from 10-40% v/vof the composition. Preferably also, citral is present in an amountranging from 5-15% v/v of the composition. Preferably also, thecinnamaldehyde or a derivative thereof is present in an amount rangingfrom 7.5-20% v/v of the composition. Preferably also, the solvent ispresent in an amount ranging from 10-40% v/v of the composition.According to a preferred embodiment of the present invention, thesurfactant is present in an amount ranging from 10-40% v/v of thecomposition. Preferably, the surfactant comprises a betaine or asultaine. According to a preferred embodiment, the surfactant comprisesa betaine and ß-Alanine, N-(2-carboxyethyl)-N-dodecyl-, sodium salt(1:1).

Preferably, the corrosion inhibiting composition further comprises ametal iodide or iodate selected from the group consisting of: cuprousiodide; potassium iodide and sodium iodide.

According to a first aspect of the present invention there is provided amethod for spotting acid in a wellbore, said method comprising the stepsof:

-   -   providing a wellbore in need of stimulation;    -   inserting a plug in the wellbore at a location slightly beyond a        predetermined location;    -   inserting a perforating tool and a spearhead or breakdown acid        into the wellbore;    -   positioning the tool at said predetermined location;    -   perforating the wellbore with the tool thereby creating a        perforated area; and    -   allowing the spearhead acid to come into contact with the        perforated area for a predetermined period.

According to a preferred embodiment of the present invention, thecorrosion inhibitor composition is effective at a temperature of up to110° C., and in some preferred compositions effective at temperature ofup to 130° C.

According to one aspect of the present invention, the corrosioninhibitor composition provides effective protection to both carbon steelalloys as well as stainless steel for the duration period the tools areexposed to the acidic composition.

BRIEF DESCRIPTION OF THE FIGURES

Features and advantages of embodiments of the present application willbecome apparent from the following detailed description and the appendedfigures, in which:

FIG. 1 is a schematic diagram illustrating the general steps accordingto a preferred method of the present invention;

FIG. 2 illustrates a side-by-side comparison of the injection procedurein pre-fracking and fracking operations, the left graph showing theconventional method and the right graph showing a preferred embodimentof the method according to the present invention; and

FIG. 3 illustrates a side-by-side bar graph comparison of the variousstage times in the pre-fracking and fracking operations, the left graphshowing a preferred embodiment of the method according to the presentinvention, the right graph showing the conventional process.

DESCRIPTION OF THE INVENTION

The description that follows, and the embodiments described therein, isprovided by way of illustration of an example, or examples, ofparticular embodiments of the principles of the present invention. Theseexamples are provided for the purposes of explanation, and notlimitation, of those principles and of the invention.

In a conventional plug and perf operation, the plug is set in the well,it is perforated by a tool (guns), then the tool is pulled out of thehole and then acid is pumped and circulated to the perforations (thisprocess can take hours sometimes) and once a feed rate is reached theybegin the frac for that stage. The process is then repeated up to thenumber of stages (over 40 in many wells).

According to a preferred embodiment of the present invention, the methodallows for an operator to pump the tools down with the spearhead acid toperforate the zone and let the acid sit over the perforations. This isfollowed by the removal of the tool from the wellbore and initiating ofthe fracturing immediately.

According to a preferred embodiment of the present invention, thismethod can save up to an average of about 1 hr per stage (up to 5 in thecase of some tight formations) at an average cost of up $20,000/hr (forthe crew) and about 30-50 m³ of water per stage. In a 50-stage well,this can translate into savings of over $1,000,000 in time plus thesaved water of up to 800,000 gallons. The potential savings from theimplementation of this method in operations in the United States alonecould reach upwards of several hundreds of millions of dollars per year.

HCl is the most commonly used acid in fracking. With this in mind, onemust understand that perforation tools are mostly made of stainlesssteel to ensure longevity. Conventional plug and perforation processesrequire the removal of the perforation guns immediately after theperforation stage otherwise the spearhead acid would destroy theperforating guns because of their propensity to attack stainless steel.A critical factor in allowing a process to have stainless steel exposedto strong acids such as HCl is the ability to control, minimize oreliminate corrosion to a level below which would render astainless-steel tool unusable after only a few uses (or even less).

According to a preferred embodiment of the present invention, the methodcan be carried out with a novel corrosion inhibitor which affordsprotection of stainless steel from damage from exposure to hydrochloricacid (HCl), this affords a never-seen-before possibility of removing astep of the pre-fracking process, thereby saving substantial time, moneyand water resources.

Preferably, the surfactant is selected from the group consisting of: asultaine surfactant; a betaine surfactant; and combinations thereof.More preferably, the sultaine surfactant and betaine surfactant areselected from the group consisting of: an amido betaine surfactant; anamido sultaine surfactant; and combinations thereof. Yet even morepreferably, the amido betaine surfactant and is selected from the groupconsisting of: an amido betaine comprising a hydrophobic tail from C8 toC16. Most preferably, the amido betaine comprising a hydrophobic tailfrom C8 to C16 is cocamidobetaine.

Preferably also, the corrosion inhibition package further comprises ananionic surfactant. Preferably, the anionic surfactant is a carboxylicsurfactant. More preferably, the carboxylic surfactant is a dicarboxylicsurfactant. Even more preferably, the dicarboxylic surfactant comprisesa hydrophobic tail ranging from C8 to C16. Most preferably, thedicarboxylic surfactant is sodium lauriminodipropionate.

Most preferred are embodiments of a corrosion inhibition packagecomprising cocamidopropyl betaine and ß-Alanine,N-(2-carboxyethyl)-N-dodecyl-, sodium salt (1:1).

According to a preferred embodiment of the present invention, whenpreparing an acidic composition comprising a corrosion inhibitionpackage, metal iodides or iodates such as potassium iodide, sodiumiodide, cuprous iodide and lithium iodide can be added as corrosioninhibitor intensifier. The iodide or iodate is preferably present in aweight/volume percentage ranging from 0.1 to 1.5%, more preferably from0.25 to 1.25%, yet even more preferably 1% by weight/volume of theacidic composition. Most preferably, the iodide used is potassiumiodide.

According to a preferred embodiment of the present invention, thecorrosion package comprises:

2-Propyn-1-ol, compd. with methyloxirane; ß-Alanine,N-(2-carboxyethyl)-N-dodecyl-, sodium salt (1:1); cocamidopropylbetaine; (±)-3,7-Dimethyl-2,6-octadienal (Citral); cinnamaldehyde; andisopropanol.

More preferably, the composition comprises 20% of 2-Propyn-1-ol, compd.with methyloxirane; 20% of ß-Alanine, N-(2-carboxyethyl)-N-dodecyl-,sodium salt (1:1); 20% of cocamidopropyl betaine; 7.5% of(±)-3,7-Dimethyl-2,6-octadienal (Citral); 12.5% cinnamaldehyde; and 20%of Isopropanol (all percentages are volume percentages). A point ofnote, the surfactant molecules comprise only roughly ⅓ of the actualcontent of the entire surfactant blend as the balance, roughly ⅔, iscomprised of water so as to control the viscosity of the surfactant whenadmixed with the other components. This is typical of surfactant blendsin this and other industries.

According to a preferred embodiment of the present the corrosioninhibitor composition comprises cinnamaldehyde or a derivative thereofselected from the group consisting of: cinnamaldehyde; dicinnamaldehydep-hydroxycinnamaldehyde; p-methylcinnamaldehyde; p-ethylcinnamaldehyde;p-methoxycinnamaldehyde; p-dimethylaminocinnamaldehyde;p-diethylaminocinnamaldehyde; p-nitrocinnamaldehyde;o-nitrocinnamaldehyde; 4-(3-propenal)cinnamaldehyde; p-sodiumsulfocinnamaldehyde p-trimethylammoniumcinnamaldehyde sulfate;p-trimethylammoniumcinnamaldehyde o-methylsulfate;p-thiocyanocinnamaldehyde; p-(S-acetyl)thiocinnamaldehyde;p-(S—N,N-dimethylcarbamoylthio)cinnamaldehyde; p-chlorocinnamaldehyde;α-methylcinnamaldehyde; β-methylcinnamaldehyde; α-chlorocinnamaldehydeα-bromocinnamaldehyde; α-butylcinnamaldehyde; α-amylcinnamaldehyde;α-hexylcinnamaldehyde; α-bromo-p-cyanocinnamaldehyde;α-ethyl-p-methylcinnamaldehyde and p-methyl-α-pentylcinnamaldehyde.

According to a preferred embodiment, the acid is an aqueous modifiedacid composition comprising: a mineral acid and an alkanolamine in amolar ratio of not more than 15:1.

According to another preferred embodiment, the acid is an aqueousmodified acid composition comprising: hydrochloric acid and analkanolamine in a molar ratio of not more than 15:1.

According to a preferred embodiment, the acid is an aqueous modifiedacid composition according to claim 2, wherein the hydrochloric acid andalkanolamine are present in a molar ratio of not more than 10:1.

According to a preferred embodiment, the acid is an aqueous modifiedacid composition according to claim 2, wherein the hydrochloric acid andalkanolamine are present in a molar ratio of not more than 7.0:1. Morepreferably, hydrochloric acid and alkanolamine are present in a molarratio of not more than 4:1. Even more preferably, hydrochloric acid andalkanolamine are present in a molar ratio of not more than 3:1.

According to a preferred embodiment, the alkanolamine is selected fromthe group consisting of: monoethanolamine; diethanolamine;triethanolamine and combinations thereof. Preferably, the alkanolamineis monoethanolamine.

According to a preferred embodiment of the present invention, the methoduses a synthetic acid composition comprising: a strong acid and analkanolamine in a molar ratio of not more than 15:1; preferably in amolar ratio not more than 10:1, more preferably in a molar ratio of notmore than 8:1; even more preferably in a molar ratio of not more than5:1; yet even more preferably in a molar ratio of not more than 3.5:1;and yet even more preferably in a molar ratio of not more than 2.5:1.

Preferably, the main components in terms of volume and weight percent ofthe composition set out above comprise an alkanolamine and a strongacid, such as HCl, nitric acid, sulfuric acid, sulfonic acid.

An alkanolamine, as per the above, contains at least one amino group,NH₂, and one alcohol group, —OH. Preferred alkanolamines include, butare not limited to, monoethanolamine, diethanolamine andtriethanolamine. More preferred are monoethanolamine, diethanolamine.Most preferred is monoethanolamine. When added to hydrochloric acid aLewis acid/base adduct is formed where the primary amino group acts as aLewis base and the proton of the HCl as Lewis acid. The formed adductgreatly reduces the hazardous effects of the hydrochloric acid on itsown, such as the fuming or vapor pressure effect, the hygroscopicity,and the highly corrosive nature.

The molar ratio of the two main components can be adjusted or determineddepending on the intended application and the desired solubilizingability. According to a preferred embodiment where the strong acid isHCl, one can increase the ratio of the HCl component to increase thesolubilizing ability of the composition while still providing at leastone of the following advantages: health; safety; environmental; andoperational advantages over hydrochloric acid.

Various corrosion inhibitors can be incorporated into an acidcomposition used in a preferred embodiment of the method according tothe present invention, such composition comprises a strong acid and analkanolamine to reduce corrosion on the steel which is contacted.

Preferably, the composition may further comprise organic compounds whichmay act as corrosion inhibitors selected from the group consisting of:acetylenic alcohols, aromatic or aliphatic aldehydes (e.g.α,β-unsaturated aldehydes), alkylphenones, amines, amides,nitrogen-containing heterocycles (e.g. imidazoline-based), iminiumsalts, triazoles, pyridine and its derivatives or salts, quinolinederivatives, thiourea derivatives, thiosemicarbazides, thiocyanates,quaternary amine salts, and condensation products of carbonyls andamines. Intensifiers which can be incorporated into compositionsaccording to the present invention are selected from the groupconsisting of: formic acid, potassium iodide, antimony oxide, copperiodide, sodium iodide, lithium iodide, aluminium chloride, bismuthoxide, calcium chloride, magnesium chloride and combinations of these.Preferably, an iodide compound such as potassium iodide is used. Otheradditives can be optionally added to a composition according to apreferred embodiment of the present invention. A non-limiting list ofsuch common additives includes iron control agents (e.g. reducingagents), water-wetting surfactants, non-emulsifiers, deemulsifiers,foaming agents, antisludging agents, clay and/or fines stabilizer, scaleinhibitors, mutual solvents, friction reducer. Alcohols and derivativesthereof, such as alkyne alcohols and derivatives and preferablypropargyl alcohol and derivatives thereof can be used as corrosioninhibitors. Propargyl alcohol itself is traditionally used as acorrosion inhibitor which works well at low concentrations. It ishowever a very toxic/flammable chemical to handle as a concentrate, socare must be taken when exposed to the concentrate. One preferredcompound to use 2-Propyn-1-ol, complexed with methyloxirane, as this isa much safer derivative to handle. Basocorr® PP is an example of such acompound. Metal iodides or iodates such as potassium iodide, sodiumiodide, cuprous iodide and lithium iodide can potentially be used ascorrosion inhibitor intensifier along with the composition according topreferred embodiments of the present invention. In fact, potassiumiodide is a metal iodide traditionally used as corrosion inhibitorintensifier, however it is expensive, but works extremely well. It isnon-regulated and safe to handle. The iodide or iodate is preferablypresent in a weight percentage ranging from 0.05 to 10 wt %, morepreferably, 0.1 to 5 wt %, more preferably from 0.2 to 3 wt %, yet evenmore preferably from 0.25 to 2 wt %.

According to a preferred embodiment of the present invention, there isprovided a method of matrix acidizing a hydrocarbon-containing limestoneformation, said method comprising:

-   -   providing a composition comprising a HCl and lysine mixture and        water; wherein the molar ratio between the HCl and the lysine        ranges from 4.5:1 to 8.5:1,    -   injecting said composition downhole into said formation at a        pressure below the fracking pressure of the formation; and    -   allowing a sufficient period of time for the composition to        contact said formation to create wormholes in said formation.

Lysine & hydrogen chloride are present in a molar ratio ranging from 1:3to 1:12.5; preferably in a molar ratio ranging from 1:4.5 to 1:9, andmore preferably in a molar ratio ranging from more than 1:5 to 1:8.5.

According to a preferred embodiment of the present invention, the acidused is neat HCl.

The corrosion inhibitor composition further comprises a metal iodide oriodate selected from the group consisting of: cuprous iodide; potassiumiodide and sodium iodide. Preferably, the metal iodide or iodate ispotassium iodide. According to another preferred embodiment of thepresent invention, the metal iodide or iodate is sodium iodide.According to yet another preferred embodiment of the present invention,the metal iodide or iodate is cuprous iodide.

Table 1 includes a prior composition (CI-5) and a composition accordingto a preferred embodiment of the present invention (CI-5SS).

TABLE 1 Composition of various tested corrosion inhibitor packages CI-5CI-5SS 2-Propyn-1-ol, compd. with methyloxirane Vol % 45 20.beta.-Alanine, N-(2-carboxyethyl)-N- Vol % 11.7 20 dodecyl-, sodiumsalt (1:1) Cocamidopropyl betaine Vol % 11.7 20(±)-3,7-Dimethyl-2,6-octadienal (Citral) Vol % 7 7.5 Cinnamaldehyde Vol% 0 12.5 Isopropanol Vol % 24.6 20 Total 100 100 Vol %Corrosion Testing

Corrosion inhibitor compositions according to preferred embodiments ofthe present invention were exposed to corrosion testing. The results ofthe corrosion tests and comparative corrosion testing are reported inTables 2 through 5. Various steel grades (stainless steel and carbonsteel) were subjected to acid compositions comprising corrosioninhibitors according to the present invention against known corrosioninhibitors to the listed compositions for various periods of time atvarying temperatures. A desirable corrosion inhibition result was onewhere the lb/ft2 corrosion number is at or below 0.05. More preferably,that number is at or below 0.02.

33% HCl:MEA in a 5.5:1 ratio and 50% HCl:MEA in a 5.5:1 ratio indicatethe volume amount of the original concentration of a stock solutioncontaining HCl and Monoethanolamine in a ratio of 5.5:1. The HCl loadingof a 33% HCl:MEA in a 5.5:1 ratio is approximately 6.5% HCl. The HClloading of 50% HCl:MEA in a 5.5:1 ratio is approximately 10% HCl.

TABLE 2 Corrosion testing of 316 steel coupons with various acidic fluidat various temperature run of 12 hours at a temperature of 90° C.Surface Steel Corrosion Loss wt area Density Mm/ type Fluid inhibitor(g) (cm2) (g/cc) Mils/yr year Lb/ft2 316 33% 1.0% CI-5 1.2899 20.9687.92 2232.38 56.702 0.126 HCl:MEA in 0.75% CI-1A a ratio of 0.1% NE-15.5:1 316 50% 1.0% CI-5 1.3647 20.968 7.92 2361.83 59.991 0.133 HCl:MEAin 0.75% CI-1A a ratio of 0.1% NE-1 5.5:1 *33% and 50% indicate thelevel of the original concentration of a stock solution containing HCland Monoethanolamine in a ratio of 5.5:1. **All percentages are given involume/volume % of the total volume of the fluid.

TABLE 3 Corrosion testing of various steel coupons with various acidicfluid at various temperature run time of 6 hours Surface Steel TempCorrosion Loss area Density Mils/ type Fluid (° C.) inhibitor wt (g)(cm2) (g/cc) yr Mm/year Lb/ft2 316 33% 90 1.0% CI-5 0.2706 20.968 7.92936.63 23.79 0.026 HCl:MEA incl 0.1% ZA in a ratio 0.75% CI-1A of 5.5:10.1% NE-1 316 33% 90 2.0% CI-5 0.5990 20.968 7.92 2073.33 52.66 0.058HCl:MEA 0.75% CI-1A in a ratio 0.1% NE-1 of 5.5:1 316 33% 90 0.75% CI-20.8117 20.968 7.92 2809.56 71.36 0.079 HCl:Urea 0.5% CI-4A in a ratio0.5% CI-1A of 1:0.7 0.1% NE-1 316 33% 90 2.0% CI-5 1.1770 20.968 7.924073.98 103.48 0.115 HCl:MEA 0.75% CI-1A in a ratio 0.1% NE-1 of 5.5:1316 33% 90 0.75% CI-2 1.1348 20.968 7.92 3927.91 99.77 0.110 HCl:MEA0.5% CI-4A in a ratio 0.5% CI-1A of 5.5:1 0.1% NE-1 316 33% 90 1.50%CI-5SS 0.1422 20.968 7.92 492.20 12.50 0.014 HCl:MEA 1.0% CI-1A in aratio 0.1% NE-1 of 5.5:1 316 33% 90 1.50% CI-5SS 0.3277 20.968 7.92756.18 19.21 0.032 HCl:MEA 1.0% CI-1A in a ratio 0.1% NE-1 of 5.5:1 31650% 90 1.50% CI-5SS 0.1974 20.968 7.92 683.27 17.36 0.019 HCl:MEA 1.0%CI-1A in a ratio 0.1% NE-1 of 5.5:1 316 33% 90 1.50% CI-5SS 0.687820.968 7.92 1587.13 40.31 0.067 HCl:MEA 1.0% CI-1A in a ratio 0.1% NE-1of 5.5:1 316 50% 90 1.50% CI-5SS 0.2246 20.968 7.92 777.41 19.75 0.022HCl:MEA 1.0% CI-1A in a ratio 0.1% NE-1 of 5.5:1 L80 33% 90 1.50% CI-5SS0.147 28.922 7.86 370.68 9.42 0.010 HCl:MEA 1.0% CI-1A in a ratio 0.1%NE-1 of 5.5:1 P110 33% 90 1.50% CI-5SS 0.112 34.839 7.86 236.15 5.9980.007 HCl:MEA 1.0% CI-1A in a ratio 0.1% NE-1 of 5.5:1 316 33% 90 1.50%CI-5SS 0.0593 20.968 7.92 205.26 5.214 0.006 HCl:MEA 1.0% CI-1A in aratio 0.1% NE-1 of 5.5:1 316 33% 110 1.50% CI-5SS 0.2499 20.968 7.92864.98 21.971 0.024 HCl:MEA 1.0% CI-1A in a ratio 0.1% NE-1 of 5.5:1 L8033% 110 1.50% CI-5SS 0.134 28.922 7.86 338.06 8.587 0.009 HCl:MEA 1.0%CI-1A in a ratio 0.1% NE-1 of 5.5:1 P110 33% 110 1.50% CI-5SS 0.15034.839 7.86 315.49 8.014 0.009 HCl:MEA 1.0% CI-1A in a ratio 0.1% NE-1of 5.5:1 QT900 33% 110 1.50% CI-5SS 0.082 34.839 7.86 171.50 4.356 0.005HCl:MEA 1.0% CI-1A in a ratio 0.1% NE-1 of 5.5:1 316 50% 110 1.50%CI-5SS 0.1675 20.968 7.92 579.77 14.726 0.016 HCl:MEA 1.0% CI-1A in aratio 0.1% NE-1 of 5.5:1 L80 50% 110 1.50% CI-5SS 0.123 28.922 7.86312.02 7.925 0.009 HCl:MEA 1.0% CI-1A in a ratio 0.1% NE-1 of 5.5:1 P11050% 110 1.50% CI-5SS 0.132 34.839 7.86 277.71 7.054 0.008 HCl:MEA 1.0%CI-1A in a ratio 0.1% NE-1 of 5.5:1 QT900 50% 110 1.50% CI-5SS 0.08434.839 7.86 176.11 4.473 0.005 HCl:MEA 1.0% CI-1A in a ratio 0.1% NE-1of 5.5:1 316 7.5% HCl 90 1.50% CI-5SS 0.0729 20.968 7.92 252.33 6.4090.007 1.0% CI-1A 0.1% NE-1 316 10% HCl 90 1.50% CI-5SS 0.0406 20.9687.92 140.53 3.569 0.004 1.0% CI-1A 0.1% NE-1 316 15% HCl 90 1.50% CI-5SS0.0254 20.968 7.92 87.92 2.233 0.002 1.0% CI-1A 0.1% NE-1 316 10% HCl 901.50% CI-5 0.0309 20.968 7.92 106.95 2.717 0.003 1.0% CA 0.1% NE-1Notes: CI-2 is a commercially available corrosion inhibitor (ASP 560)NE-1 is a non-emulsifier. CI-4A is propargyl alcohol with methyloxirane.CI-1A is potassium iodide ZA refers to cinnamaldehyde

TABLE 4 Corrosion testing carried out at 110° C. for a duration of 6hours on various types of steel Surface Steel Corrosion Loss wt. areaDensity type Fluid inhibitor (g) (cm2) (g/cc) Mils/yr Mm/year Lb/ft2 31650% 1.50% CI-5SS 0.1675 20.968 7.92 579.77 14.726 0.016 HCl:MEA 1.0%CI-1A in a ratio 0.1% NE-1 of 5.5:1 L80 50% 1.50% CI-5SS 0.123 28.9227.86 312.02 7.925 0.009 HCl:MEA 1.0% CI-1A in a ratio 0.1% NE-1 of 5.5:1P110 50% 1.50% CI-5SS 0.132 34.839 7.86 277.71 7.054 0.008 HCl:MEA 1.0%CI-1A in a ratio 0.1% NE-1 of 5.5:1 QT900 50% 1.50% CI-5SS 0.084 34.8397.86 176.11 4.473 0.005 HCl:MEA 1.0% CI-1A in a ratio 0.1% NE-1 of 5.5:1

TABLE 5 Corrosion testing at 90° C. for a duration of 6 hours forstainless steel 316 coupons having a density of 7.92 g · cc and surfacearea of 20.968 cm2 Corrosion Wt loss Mils/ Mm/ Lb/ Fluid inhibitor (g)yr year ft2 7.5% HCl 0.50% CI-5SS 0.0970 335.75 8.528 0.009 0.33% CI-1A0.033% NE-1 10% HCl 0.50% CI-5SS 0.0838 290.09 7.368 0.008 0.33% CI-1A0.033% NE-1 15% HCl 0.50% CI-5SS 0.0967 334.71 8.502 0.009 0.33% CI-1A0.033% NE-1 10% HCl 0.50% CI-5 0.1729 598.46 15.201 0.017 0.33% CI-1A0.033% NE-1 33% HCl:Urea 1.50% CI-5SS 0.7512 2600.15 66.044 0.073 in aratio of 1:0.7 1.0% CI-1A 0.1% NE-1 10% HCl No CI 2.4590 8511.40 216.1890.239

The corrosion testing results obtained indicate, in the preferredcorrosion inhibitor developed, CI-5SS, the need for both an alkynealcohol (propargyl alcohol) and cinnamaldehyde. Separately, they did notprovide corrosion protection sufficient to allow the novel methoddisclosed herein to be implemented. The difficulty with the use ofcinnamaldehyde is to maintain it dispersed at higher temperatures suchas 90° C. to 110° C. The surfactant package used according to apreferred embodiment of the present invention is capable of providingsuch cinnamaldehyde dispersion but requires higher loadings than usual.Citral has shown some effectiveness for the prevention of pitting athigher temperatures (even 110° C. to 120° C.). The cinnamaldehyde is aneffective film former at these temperatures and by was able to protectthe stainless steel.

The testing results confirms the feasibility of a widespreadimplementation of the method according to a preferred embodiment of thepresent invention where the step of removing a perforating tool prior toinjection of the spearhead acid composition. The inventors have alsonoted that by carefully balancing the acidic composition % content ofactive acid (for example HCl) with an appropriate corrosion inhibitor orblend of several components to obtain a good performance corrosioninhibitor one may apply this type of method to various other oilfielddownhole operations where the acidic composition comprises a corrosioninhibitor and is sufficiently balanced to complete said operationswithin a reasonable time period which will leave the tool with minimalcorrosion damage from exposure to the acidic composition.

The inventors have also noted that by diluting an initial concentratedacidic composition (whether it is HCl or a modified acid comprising anHCl component therein) and where said initial concentrated acidiccomposition already comprises a corrosion inhibitor package, thecorrosion protection performance can be noticeably worse in a dilutedcomposition as the CI components are fewer for a similar volume of acid.This surprising result has been more noticeable at elevated temperaturesbut should be understood to be part of the acidic composition blendingstrategy when “balancing” the acidic composition and its CI content. Oneway to balance the diluted acidic composition is to add one or more oreven all of the CI components originally present in the CI package inthe undiluted acidic composition. Another component to consider whenbalancing the acidic composition is to determine the downhole materialsencountered as well as the casing and the tools (which are typicallymade of stainless steel.

Balancing comprises, among other things, altering the pH constantly asthe dissolved cement raises the pH of the system as it is drilled out.It is desirable to maintain the minimal pH required “only” so as toincrease the rate of penetration (ROP) to the optimal rate. Usually, thecement is not drilled out with pure acid (unless very tough drilling ormaybe only to initiate the job) so as to control costs, reduce corrosionconcerns etc. 10. The method according to claim 8, wherein the acidcomprises an HCl component.

According to a preferred embodiment, the balancing of the acidiccomposition is done by adding more of at least one of the componentspresent in the corrosion inhibitor package itself present in theundiluted acidic composition.

According to a preferred embodiment, the balancing of the acidiccomposition is done by altering the pH constantly as the dissolvedcement raises the pH of the system as it is being dissolved by theacidic composition.

Typically, to perform and plug and perf operation, the concentration ofthe acid can vary from 4% (equivalent HCl content) to 15% (eq. HCl). Onecan perform at higher % but would not get much additional benefit andmay cause some unwanted damage or unnecessary corrosion. Preferably, anacidic composition comprising a 7.5% (equivalent HCl content) is mostoften used to perform plug and perf operations. According to a preferredembodiment, the CI package and content is determined in accordance inorder to optimize the financial aspect of the operation. This involvesbalancing the acidic composition (HCl eq. content), the CI package(price and performance) and value of the damage to the bottom holeassembly tool as well as the coil tubing or wireline or slickline usedduring the operation.

The inventors have noted that, surprisingly, modified acids containingurea are not desirable as they have a stability upper limit ofapproximately 80° C. Above this temperature, the urea component startsto decompose yielding CO₂ and ammonia, thereby neutralizing the acidiccomponent and therefore, it would not be the ideal candidate forspearhead or wireline deployed spearhead operations as most operationsare performed at temperatures close to or above 80° C. Corrosioninhibitor compositions according to preferred embodiment of the presentinvention have shown excellent versatility and stability at hightemperature (up to 190° C.) between conventional acids (HCl) andmodified acids (HCl:MEA) as well as steel types (QT900 (stainlesssteel); P110 (carbon steel); L80 (carbon steel); 316 (stainless steel).

As illustrated in FIG. 1, pumping acid downhole while the wireline andperforating tool is present downhole has been shown in the field tosave, in some instances 15 minutes per perforation operation. Moreover,the savings of water are equally staggering. The following is but a listof substantial advantages of performing such a process: combiningpumping down the plug with displacing the ball and acid; reducingpumpdown cycle time; reducing fluid volumes required. The concerns notedby the operators were the following: defining fluid bypass around theplug; the method was dependent on the rate the plug was being pumped;and the rate achieved for pumpdown was variable from stage to stage.

Example 1—Wireline Testing Experiments

Specific tests for a modified acid composition comprising analkanolamine:HCl blend (present in a molar ratio of 1:6.4 alsocontaining a corrosion inhibitor package)(diluted to one third of itsstock solution, i.e. 33%) and a commercialised 7.5% HCl acid blend(containing a CI package) spearhead blend were performed on wire linesamples to simulate long term field exposure conditions under extremeconditions at the request of a global oil company. Due to cool downeffect and limited real world exposure times, these tests would beindicative of a long-term duty cycle.

The tensile strength and corrosion tests were executed on wire linesamples provided by Company B. One sample was exposed to 33%alkanolamine:HCl composition and another sample was exposed to the 7.5%HCl acid blend for 96 and 120 consecutive hours at 90° C. (194° F.) at600 psi. The weight loss of the wire line samples is expected to beattributed not only the corrosion of the steel but also the degradationof the binding material. After the corrosion test cycle, tensilestrength testing was conducted on two strands pulled from the wire lineexposed to the 33% alkanolamine:HCl composition. The tensile strengthvalues for each strand were equal to control samples that were notexposed to the acid. Tensile strength testing was not performed on thewire line exposed to the 7.5% HCl acid blend due to excessive corrosion.

Example 2—P110 Coupon Corrosion Tests

Long term corrosion tests on P110 coupons with a 33% alkanolamine:HClcomposition and the 7.5% HCl acid blend at 90° C. (194° F.) were alsocarried out. The corrosion properties of the 33% % alkanolamine:HClcomposition was observed to provide superior protection in comparison tothe 7.5% HCl acid blend over a long time period. The testing allows toselect an ideal composition which will minimize corrosion to thewireline over a number of plug and perf operations. However, it shouldbe noted that a less than optimal acidic composition (comprising acorrosion inhibitor) may be employed in order to substantially reducetime spent on pre-frac operations, minimize water volumes used andtherefore, provide a financial advantage of performing this method aswell as a substantial water usage reduction over the conventionalapproach used prior to this novel process.

Procedure: To determine the corrosion properties of unspent 33%alkanolamine:HCl composition and the 7.5% HCl acid blend (containing aCI package), the acid blends were evaluated at 90° C. (194° F.) on P110coupons for 96 hours (4 days) at ambient pressure. The corrosion testswere executed in samples jars in a water bath. The corrosion rates weredetermined from the weight loss after the coupons were washed and dried.

Results: The testing results confirms the feasibility of a widespreadimplementation of the method according to a preferred embodiment of thepresent invention where the step of removing a perforating tool prior toinjection of the spearhead acid composition is removed and the toolremains downhole during the acid breakdown step.

Example 3—Field Trial

A major E&P company operating in Western Canada performing horizontalmulti-stage slickwater completions on multi well pads. Using plug andperf completion technique they were targeting the Duvernay and Montneyformations. Reservoir temperatures were approximately 230° F.Historically 15% HCl acid was used to breakdown the formation and assistin fracture propagation.

Approximately 97,500 gals of a modified acid using an alkanolamine:HClcomposition with a corrosion package was delivered to location.Dilutions ranged from a 2-1 water-acid ratio to yield a 33% modifiedacid concentration and 1-1 for a 50% dilution. The blended modified acid(1300 gal) was placed in the wellbore and then the wireline and pumpdowncrews continued to the next well. As the treatment commenced, crewsdisplaced acid to perforations with frac water. Once the acid reachedthe perforations an immediate pressure drop was observed, all frac pumpswere brought on-line to pre-engineered rates and operations commenced.FIG. 2 illustrates the time advantage of using an embodiment of themethod of the present invention (right graph) in comparison to theconventional method (left graph).

A significant pressure drop was observed as the acid reached theperforations and it was noted that breakdowns looked very similar tothat obtained with 15% HCl which had been previously pumped on the samepad. Both the service company and operator were very pleased with theperformance, ease of use of the acid while utilizing a technicallyadvanced, safer and more environmentally responsible product along witheliminating corrosion concerns was a major value add to the customer andall involved with the project. The modified acid composition allowed thecompany to have confidence that the casing metals were free fromhydrogen embrittlement and any corrosion related issue that would havearisen by utilizing HCl. This time saving method would not be possiblewith any existing HCl blends offered in the market. Observations by thecrew included the time savings. Moreover, the company and pumping crewson location had the opportunity to use an acid which has an inherentsafety profile adapted to minimize or eliminate the extremely dangerousproperties associated with 15% HCl. Some of the safety factors include:less-corrosive to dermal tissue; low-vapor pressure effect (fuming);low-toxicity (Calculated LD-50 Rat); lower bioaccumulative effect; andbiodegradable.

Along with the safety aspect of the acid composition used, there is alsothe technical advantages it brought to the operations: low corrosionproperties—<0.02 lb/ft² for more than 24 hrs; pump acid with wirelineBHA (save time and water); in the event of surface equipment failureoccur, there is no need to flush acid out of wellbore; the compositionis hauled as a concentrate and diluted on location; provides the abilityto adjust acid strength for tougher breakdowns; fewer acid trucks on theroad (landowner optics); it is a class one product (chemicals will notseparate out over time); and it can be diluted with available water(produced/sea water/fresh). Additional benefits of the modified acidused in the example include: ultra-low long term corrosion effects (168hrs); no precipitation of solubilized Ca post pH increase (eliminatingrisks of formation damage); clear: low fuming/vapor pressure; aggressivereaction rates on stimulations and workovers; custom blend allowingspotting of acid with perforating guns via wireline; compatible withtypical elastomers used in oil and gas; allows to adjust concentrationson the fly to target optimal pay zones; and it has a high thermalstability up to ˜190° C.

Example 4—Field Trial #2

Another large Oil and Gas company carried out wireline plug and perfoperations and collected the below information in terms of performance.The average time from start of pumping to start of sand was determinedto be 8.2 mins faster for wireline stages where the tools and wirelinewent downhole together, compared to the average of all other stages. Theaverage stage pump times were determined to be 9.4 mins lower for theWireline stages where acid was injected along with the perforating tooland wireline, compared to average of all other stages. See FIG. 3 whichhighlights the difference in time for each step.

The company using the method according to a preferred embodiment of thepresent invention, noted the following spearhead operationalefficiencies: the ability to pump acid with wire line and BHA (guns andbridge plug); the elimination of the need to displace acid afterwireline is out of the hole; the reduced water requirements; savings ofat least one hole volume per frac (>10,000 gal water reduction perstage); allowing acid to be spotted over the entire perf intervalcluster; more effective cluster breakdown; increased frac crewefficiency; and shorter time to initiate the frac and get to job rates.

Example 5—Corrosion Testing on Various Wirelines

Corrosion testing was carried out on various manufacturers' wirelinesusing an acidic composition comprising an alkanolamine:HCl blend with acorrosion inhibitor package. The wireline material of four differentmanufacturers were tested corrosion resistance at a temperature of 130°C. and at 400 psi for periods of time ranging up to 24 hours ofexposure. Table 7 (below) provides a summary of the corrosion data fromthis testing series.

TABLE 7 Corrosion Test Results of 33% composition comprising MEA:HCl (in1:4.1 molar ratio) at 130° C. (266° F.) at 400 psi over various timeperiods Cumulative Weight Loss 6 hrs 12 hrs 18 hrs 24 hrs Test Samplemm/yr lb/ft² mm/yr lb/ft² mm/yr lb/ft² mm/yr lb/ft² A #1 clear wire19.727 0.022 22.121 0.024 25.423 0.028 28.146 0.031 B #2 clear wire18.902 0.021 20.800 0.023 23.854 0.026 — — C #3 clear wire 19.810 0.02223.772 0.026 27.651 0.030 — — D Sanded wire 17.334 0.019 20.470 0.02223.277 0.026 28.229 0.031

The results support the applicability and feasibility of the methodaccording to a preferred embodiment of the present invention. Moreover,more optimal compositions falling within the scope of the presentinvention can be developed in order to obtain better financial,water-savings and/or corrosion results over conventional processes.

According to another aspect of the present invention, there is provideda method to perform a downhole operation for drilling with acid toincrease ROP (rate of penetration) through cement plugs, said methodcomprises the following steps:

-   -   inserting a drilling tool inside a wellbore;    -   injecting an acidic composition concurrently with the drilling        tool;    -   position the drilling tool within the wellbore at a point        requiring drilling;    -   contacting the surface requiring drilling with the acid and        begin drilling; and    -   continue the drilling operation until desired distance has been        achieved;        where the acidic composition comprises a corrosion inhibitor        package as described above and is sufficiently balanced to        complete the operation of dissolving the acid soluble debris        within a time period which will leave the tool with acceptable        (in some cases, minimal) corrosion damage from exposure to the        acidic composition.

According to another aspect of the present invention, there is provideda method to perform a downhole operation for coiled tubing deployed acidwashes, said method comprises the following steps:

-   -   inserting a coiled tubing inside a wellbore;    -   injecting an acidic composition concurrently with the drilling        tool;    -   position the drilling tool within the wellbore at a point        requiring drilling;    -   contacting the surface requiring drilling with the acid and        begin drilling; and    -   continue the drilling operation until desired distance has been        achieved,        where the acidic composition comprises a corrosion inhibitor        package as described above and is sufficiently balanced to        complete the operation of dissolving the acid soluble debris        within a time period which will leave the tool with acceptable        (in some cases, minimal) corrosion damage from exposure to the        acidic composition.

According to another aspect of the present invention, there is provideda method to perform a downhole operation for coiled tubing deployedfilter cake treatments said method comprises the following steps:

-   -   inserting a coiled tubing inside a wellbore;    -   injecting an acidic composition concurrently with the coiled        tubing    -   position the coiled tubing within the wellbore at a point        requiring a treatment on said filter cake;    -   contacting the surface requiring treatment with the acidic        composition; and    -   allow contact between the acidic composition and the filter cake        until the filter cake has been effectively treated or removed        from the walls of the wellbore,        where the acidic composition comprises a corrosion inhibitor        package as described above and is sufficiently balanced to        complete the operation of dissolving the acid soluble debris        within a time period which will leave the tool with acceptable        (in some cases, minimal) corrosion damage from exposure to the        acidic composition.

It is often desirable to seal tubing or other pipe in the casing of thewell, for example when cement or another type of slurry must be pumpeddown the tubing and force the slurry out into a formation. In suchinstances, one must be able to seal the tubing with respect to the wellcasing and to prevent the fluid pressure of the slurry from lifting thetubing out of the well. This can be accomplished by packers and bridgeplugs as well as ball in cage valves.

According to another aspect of the present invention, there is provideda method to perform a downhole operation for dissolving plugs and balls;wherein said method comprises the following steps:

-   -   injecting an acidic composition down the wellbore at a position        proximate said ball;    -   allowing sufficient contact time for the acidic composition to        dissolve ball to allow further processing to occur,        where the acidic composition comprises a corrosion inhibitor        package as described above and is sufficiently balanced to        complete the operation of dissolving the acid soluble debris        within a time period which will leave the tool with acceptable        (in some cases, minimal) corrosion damage from exposure to the        acidic composition.

According to another aspect of the present invention, there is provideda method to perform a downhole operation for slower (matrix) rateisolated (thru coil) acid stimulations, wherein said method comprisesthe following steps:

-   -   providing a wellbore comprising at least one area requiring        matrix acidization;    -   injecting an acidic composition down the wellbore at a position        proximate said area requiring matrix acidization;    -   allowing sufficient contact time for the acidic composition to        perform the matrix acidization step;    -   optionally, remove the tool;    -   optionally, further process the acidized formation,        where the acidic composition comprises a corrosion inhibitor        package as described above and is sufficiently balanced to        complete the operation of dissolving the acid soluble formation        within a time period which will leave the tool with acceptable        (in some cases, minimal) corrosion damage from exposure to the        acidic composition.

According to another aspect of the present invention, there is provideda method to perform a downhole operation for fishing tools in thepresence of an acid to consume debris on top of the tool trying to berecovered, wherein said method comprises the following steps:

-   -   injecting an acidic composition down the wellbore concurrently        with a fishing tool at a position proximate a said ball;    -   allowing sufficient contact time for the acidic composition to        dissolve ball to allow further processing to occur,        where the acidic composition comprises a corrosion inhibitor        package as described above and is sufficiently balanced to        complete the operation of dissolving the acid soluble debris        within a time period which will leave the tool with acceptable        (in some cases, minimal) corrosion damage from exposure to the        acidic composition.

According to another aspect of the present invention, there is provideda method to perform a downhole operation for stuck coil or tools incasing, where the sticking is caused by an acid soluble debris, saidmethod comprising the steps of:

-   -   injecting an acidic composition in the wellbore;    -   directing the acidic composition at a point within the wellbore        where said coil is stuck    -   allowing the acidic composition sufficient contact time at and        near said area to allow the acid soluble debris to be dissolved        by the acidic composition,        where the acidic composition comprises a corrosion inhibitor        package as described above and is sufficiently balanced to        complete the operation of dissolving the acid soluble debris        within a time period which will leave the tool with acceptable        (in some cases, minimal) corrosion damage from exposure to the        acidic composition.

Preferably, the following are some of the tools that may be used as partof a bottom hole assembly (BHA): drilling motors; washing tools;perforating guns; fishing tools; plugs; balls; any BHA with a highstainless steel metal content in general.

According to another aspect of the present invention, there is provideda method to perform a debris and scale management inside wellbores whenhaving both a tool and an acid present at the same time. According to apreferred embodiment of a method of the present invention, one canperform spotting acid to dislodge stuck pipes inside a wellbore.Preferably, coiled tubing or a BHA (bottom hole assembly) injected intothe wellbore can help free downhole in situ items like chokes orflow-controls, safety valves, etc. According to a preferred embodimentof a method of the present invention, one can perform an operation toclean a wellbore with a reaming tool in the presence of an acid.

According to another aspect of the present invention, there is provideda method to perform a downhole operation for spotting acid in awellbore, said method comprising the steps of:

-   -   providing a wellbore in need of stimulation;    -   inserting a plug in the wellbore at a location slightly beyond a        predetermined location;    -   inserting a perforating tool and a spearhead or breakdown acid        into the wellbore;    -   positioning the tool at said predetermined location;    -   perforating the wellbore with the tool thereby creating a        perforated area; and    -   allowing the spearhead acid to come into contact with the        perforated area for a predetermined period of time sufficient,        where the acidic composition comprises a corrosion inhibitor        package as described above and is sufficiently balanced to        complete the operation of dissolving the acid soluble debris        within a time period which will leave the tool with acceptable        (in some cases, minimal) corrosion damage from exposure to the        acidic composition.

While the foregoing invention has been described in some detail forpurposes of clarity and understanding, it will be appreciated by thoseskilled in the relevant arts, once they have been made familiar withthis disclosure that various changes in form and detail can be madewithout departing from the true scope of the invention in the appendedclaims.

The invention claimed is:
 1. A method for the fracking or stimulation ofa hydrocarbon bearing formation, said method comprising the steps of:providing a wellbore and a casing in said wellbore; inserting a plug inthe wellbore at a predetermined location; inserting a perforating tooland an acidic composition into the wellbore, wherein said acidiccomposition comprises a corrosion inhibiting composition comprising aterpene, an amphoteric surfactant, and a solvent, and wherein saidacidic composition is in direct contact with both said perforating tooland casing; positioning the perforating tool by a wireline within theacidic composition near said predetermined location, wherein the acidiccomposition is in contact with at least one of the wireline and theperforation tool when the acidic composition, the wireline and the toolare inserted into the wellbore; perforating the wellbore with theperforating tool thereby creating a perforated area and acid solubledebris; allowing the acidic composition to come into contact with theperforated area and acid soluble debris for a predetermined period oftime to prepare the formation for the stimulation; removing theperforating tool from the wellbore; and initiating the fracking orstimulation of the perforated area using a stimulation fluid.
 2. Themethod of claim 1, wherein the corrosion inhibitor is adapted to preventdamaging corrosion to the perforating tool during exposure with saidacidic composition.
 3. The method according to claim 1, wherein theperforating tool is a perforating gun.
 4. The method according to claim1, wherein the acidic composition is selected from the group consistingof: mineral acids; organic acids; synthetic acids; and combinationsthereof.
 5. The method according to claim 1, wherein the acidiccomposition comprises an HCl component.
 6. The method according to claim1, wherein the acidic composition is selected from the group consistingof: HCl; HCl:amino acid; HCl:alkanolamines; and combinations thereof. 7.The method of claim 1, wherein: wherein the acidic composition is incontact with said wireline and the perforation tool when the acidiccomposition, the wireline and the tool are inserted into the wellbore.